Horizontal Well Completions

Transcription

1 Horizontal Well Completions Objectives To provide a clear, applications oriented view of horizontal well completions and workovers. To enable the class participant to design an effective horizontal well completion. What data to collect and why it is important How to select a candidate What computer models to use / Who can help What completion is probable, possible and practical What to expect on production / How to operate it How to design it. 3/14/2009 1

2 Horizontal Wells First conceived in US and USSR in 1930 s First serious attempts in 1950 s First successful completions in 1970 s Caught on world-wide in 1980 s Now a standard well configuration 3/14/2009 2

3 Slide modified from BP 3/14/2009 3

4 Uses of Horizontal Wells increasing reservoir contact water/gas coning control water/steam injection extended reach capability minimizing surface locations, slot saving improving wellbore location prospecting and gathering reservoir info. drain individual compartments 3/14/2009 4

5 Other Uses Prospecting - as a tool to prove up seismic in an area Accessing all parts of the field - flank wells a favorite in offshore reservoirs As a platform for fracturing As a gathering system - Amoco Canada s Big Kahuna 3/14/2009 5

6 Favorite Targets Naturally fractured chalks and shales Water coning problem areas Field edges 3/14/2009 6

7 Best Candidates from a Reservoir Perspective 1. Must still have good volume of reserves, pressure and fluids of value. 2. Permeability values (horizontal and vertical) more a design consideration than a limit. 3. Oil was thought to be a better candidate than gas because of hydraulic fracturing, however, horizontal wells with multistage fracturing are a common completion for low permeability gas plays. 3/14/2009 7

8 Best - non stimulated candidates No vertical barriers and generally high permeability reservoirs. Kv/Kh > 0.1 to 0.5 (opinion) (consider frac if perm is too low) natural fractures often viewed as good, but watch effects on the drainage profile and also bottom water. 3/14/2009 8

9 Red Flags - for unstimulated horizontals Poor quality reservoirs - need something to start with. Very low Kv, vertical flow barriers Some extremely thick zones 3/14/2009 9

10 Reservoir Considerations Will reduced footprint help? (offshore and high land cost or political areas) Will there be improvements in contact with some dipping beds. Pay configuration issues: layers boundries anisotrophy 3/14/

11 Permeability Variance K h, K H, K v Barriers Bed angle (a vertical well can be horizontal to the bedding plane in some instances 3/14/

12 Directional Permeability 3/14/

13 Permeability Contribution from Vertical and Horizontal Permeability 3/14/

14 Drainage in a Horizontal Well for Cases of Permeability Anisotrophy 3/14/

15 Placement of the Horizontal Above the O/W Contact Depends on: vertical permeability fluid viscosities pay zone thickness anomolies in the zone depth (?) and formations above the pay zone 3/14/

16 Pay Zone Thickness no minimum or optimum vertical and horizontal permeability more critical fractures incidence of fractures location of fractures permeability of fractures good or bad? - water??? 3/14/

17 When is a Multi-lateral Required? Wherever compartmentalization reduces the ability of a single wellbore (stimulation?) to effectively and economically drain the reservoir. 3/14/

18 Stacked and Opposed 3/14/

19 Compartment Recognition Geological clues DST s Production behavior Hydrocarbon source variances (oil fingerprinting) Early Recognition - addressed in design Later Recognition - requires a workover 3/14/

20 A two flow period test of reservoir Information available from downhole gauges and flow tests. Reservoir pressure Perm estimates Depletion Barriers Damage Compartmentalization potential what does it tell? 3/14/

21 Recognizing Compartmentalization Slide from George Tews 3/14/

22 Horizontal Well Expectations Uncertainty??? can it be drilled? can it be completed? can it be operated/produced? is it really a good candidate? is fracturing needed? 3/14/

23 Horizontal and Lateral Drilling An introduction to horizontal well drilling technology: Goal is to make the engineer/foreman aware of some problems and solutions available in drilling operations that can have a major effect on completions and production. 3/14/

24 Types of Horizontal Kick-Off designs. Increasing the angle limits weight transfer to the bit. Long radius wells at 2 to 6 o are used for extended reach. Medium radius wells at 6 to 8 o minimize drilling but lose some extension capacity. Short radius wells over 8 to 10 o can miss problem zones above the pay, but are short. 3/14/

25 Ability to Lift Cuttings Must reach high enough velocities to carry particles upward. Problems in horizontals: limited circulation rate large annular areas = low flow velocity striated flow regimes especially at 30 o to 60 o difficult in all liquid systems (rate) difficult in all gas systems (striation) 3/14/

26 Cuttings Beds Symmetric suspension - constant concentration in cross section Asymmetric suspension - all carried, but more at bottom Moving bed - like a dune Stationary bed - builds to height dictated by flow rate Boycott settling - explains severe solids drop out in the 30 to 60 degree range. 3/14/

27 Boycott Settling Gas Rise Rate??? Vertical holes ft/hr 30 to 60 o deviation to 7000 ft/hr Region of greatest settling Problems, 30 to 60 degrees the Boycott Region Lighter fluids rise to the top side of the wellbore (striatation) and dense fluids and cuttings drop out to the bottom out of the fast moving upper fluids result is poor hole cleaning and sticking of strings. 3/14/

28 Consequences of Poor Hole Cleaning Bridging - sticking pipe Failure to run to bottom Debris in perfs Emulsions and scale seeds left in the well? Cave-ins? - probably not 3/14/

29 Where are the casing set points in this example? 3/14/

30 BUT, is it stable as the hole approaches horizontal? Remember that hole stability is lowest in the bend area. 3/14/

31 Drilling Fluid Operating Window Mud density must be higher than the pore pressure to keep fluids from entering the well. Mud density must control tendency of shale to spall particles into wellbore Mud density must be less than the formation fracture (extension) gradient corrected for friction pressures while circulating. The pressure exerted by the fluid at any depth is a function of its density plus the friction pressure in the circulating path back to the surface. 3/14/

32 Drilling Wellbore Stability Issues - during drilling, completion and production Destabilizing Mechanism support pressure too low (spalling) support pressure too high (fracturing) Rx with drilling fluids (sloughing, swelling) formation stress unloading 3/14/

33 3/14/

34 3/14/

35 A model of wellbore stability (most stressed regions in blue) of a horizontal wellbore. 3/14/

36 Broad Based Conclusion Most Important Failure Factors pore pressure prediction weak, fissible beddling planes low support pressures time dependent loss of strength Open holes best in stable formations (carbonates, clastics) Most instability problems in the shales 3/14/

37 So, how far do you drill? Consider edge boundries Consider drilling costs (usually low in lateral) Consider vertical perm 3/14/

38 1000 Effect of length and horizontal permeability on PI in horizontal wells P.I. (Mscfd/psi) Drilled length x Kh Hariot-Watt Horizontal Study ppt 3/14/

39 P.I. (Mscfd/ m(p)) Effect of horizontal well factors on PI A field B field C field D field F field G field I field J field N field Length x (KvKh)^0.5 Hariot-Watt Horizontal Study 3/14/ ppt

40 Undulation Problems Within the Horizontal Well How long a well can you effectively complete and produce? Depends on shape, angle, path and fluids. 3/14/

41 Improving Artificial Lift for Horizontal Wells by Using Rat Hole on Short Radius 3/14/

42 Production Index Factors (a comparison to horizontal well performance) Theoritical PIF s may range from 1 to 8. Actual PIF s range from 1 to about 4 or 5. Causes: reservoir not homogeneous reservoir estimates too generous completion design was an after-thought 3/14/

43 Horizontal Well PIF s (1300 well study) Reservoir Type PIF Average (Mean) Conventional Reservoirs 4 Heavy Oil Reservoirs 7 Fractured Reservoirs 12 All reservoirs comb. 5 PIF = Prod. Improvement Factor: comparison of horizontal to vertical prod of wells at the same location. 3/14/

44 Lower Than Expected Production? 1. Low vertical perm. 2. Formation damage 3. Reservoir quality variance 4. Pressure drop along the lateral?? - few psi at max, but can be important. 5. Poor initial knowledge and assumptions. 3/14/

45 Pay Thickness Effect PIF NP = 25' NP = 50 ft NP = 75' NP = 100' NP=150' Horiz Length PEI, Nov 97 3/14/

46 Effect of Kh/Kv PIF kh/kv=1 kh/kv=5 kh/kv=10 kh/kv=25 kh/kv= Horiz Length, ft PEI, Nov 97 3/14/

47 Horiz vs Frac Xf equivalent horizontal George E. length, King Engineering ft PEI, Nov 97 kh/kv=1 kh/kv=5 kh/kv=10 kh/kv=25 kh/kv=50 3/14/

48 Horizontal Uses? Consider them any time a well is designed. Particularly good for: Coning control, Extending reach, Increasing reservoir contact, Lowering drawdown per unit area, As a platform for multiple fracture stimulation In some water injector projects. 3/14/